The aggregate amount of capitalized costs of oil and natural gas properties and related accumulated depreciation, depletion and amortization as of September 30 is as follows:

	2018			2017
Producing properties	$	427,448,584		$	434,571,516
Non-producing minerals		12,378,395			7,243,802
Non-producing leasehold		185,124			185,125
Exploratory wells in progress		-			-
		440,012,103			442,000,443
Accumulated depreciation, depletion and amortization		(242,169,604	)		(245,640,247	)
Net capitalized costs	$	197,842,499		$	196,360,196

For the years ended September 30, the Company incurred the following costs in oil and natural gas producing activities:

The following unaudited information regarding the Company’s oil, NGL and natural gas reserves is presented pursuant to the disclosure requirements promulgated by the SEC and the FASB.

Proved oil and natural gas reserves are those quantities of oil and natural gas which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes: (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or natural gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities.

The independent consulting petroleum engineering firm of DeGolyer and MacNaughton of Dallas, Texas, calculated the Company’s oil, NGL and natural gas reserves as of September 30, 2018, 2017 and 2016.

The Company’s net proved oil, NGL and natural gas reserves, which are located in the contiguous United States, as of September 30, 2018, 2017 and 2016, have been estimated by the Company’s Independent Consulting Petroleum Engineering Firm. Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007).” The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data and production history.

All of the reserve estimates are reviewed and approved by our Vice President of Operations, Freda Webb, who reports directly to our President and CEO. Ms. Webb holds a Bachelor of Science Degree in Mechanical Engineering from the University of Oklahoma, a Master of Science Degree in Petroleum Engineering from the University of Southern California and a Professional Engineering License in Petroleum Engineering in the State of Oklahoma. Ms. Webb has more than 35 years of experience in the oil and gas industry. Before joining the Company, she was sole proprietor of a consulting petroleum engineering firm and a mineral acquisition company. Ms. Webb held various positions of increasing responsibility at Southwestern Energy Company and Occidental Petroleum Corporation, with reservoir engineering assignments in several field locations across the United States. She is an active member of the Society of Petroleum Engineers (SPE).

Our Vice President of Operations and internal staff work closely with our Independent Consulting Petroleum Engineers to ensure the integrity, accuracy and timeliness of data furnished to them for their reserves estimation process. We provide historical information (such as ownership interest, oil and gas production, well test data, commodity prices, operating costs and handling fees, and development costs) for all properties to our Independent Consulting Petroleum Engineers. Throughout the year, our team meets regularly with representatives of our Independent Consulting Petroleum Engineers to review properties and discuss methods and assumptions.

When applicable, the volumetric method was used to estimate the original oil in place (OOIP) and the original gas in place (OGIP). Structure and isopach maps were constructed to estimate reservoir volume. Electrical logs, radioactivity logs, core analyses and other available data were used to prepare these maps as well as to estimate representative values for porosity and water saturation. When adequate data was available and when circumstances justified, material balance and other engineering methods were used to estimate OOIP or OGIP.

Estimates of ultimate recovery were obtained after applying recovery factors to OOIP or OGIP. These recovery factors were based on consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties and the production histories. When applicable, material balance and other engineering methods were used to estimate recovery factors. An analysis of reservoir performance, including production rate, reservoir pressure and gas-oil ratio behavior, was used in the estimation of reserves.

For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-decline curves, reserves were estimated only to the limits of economic production or to the limit of the production licenses, as appropriate.

Accordingly, these estimates should be expected to change, and such changes could be material and occur in the near term as future information becomes available.

Net quantities of proved, developed and undeveloped oil, NGL and natural gas reserves are summarized as follows:

	Proved Reserves
	Oil			NGL			Natural Gas			Total
	(Barrels)			(Barrels)			(Mcf)			Bcfe
September 30, 2015		7,038,430			2,920,600			120,214,044			180.0

Revisions of previous estimates		(1,552,010	)		(1,192,143	)		(47,068,144	)		(63.5	)
Acquisitions (divestitures)		-			-			-			-
Extensions, discoveries and other additions		303,922			65,306			16,864,075			19.1
Production		(364,252	)		(171,060	)		(8,284,377	)		(11.5	)
September 30, 2016		5,426,090			1,622,703			81,725,598			124.0

Revisions of previous estimates		253,481			407,250			13,651,501			17.6
Acquisitions (divestitures)		(37,724	)		(12,953	)		(669,064	)		(1.0	)
Extensions, discoveries and other additions		178,497			541,557			34,681,614			39.0
Production		(310,677	)		(173,858	)		(8,194,529	)		(11.1	)
September 30, 2017		5,509,667			2,384,699			121,195,120			168.6

Revisions of previous estimates		(1,407,995	)		303,728			(29,247	)		(6.7	)
Acquisitions (divestitures)		236,690			24,765			(1,782,949	)		(0.2	)
Extensions, discoveries and other additions		1,982,624			476,174			9,400,374			24.2
Production		(336,564	)		(255,176	)		(8,721,262	)		(12.3	)
September 30, 2018		5,984,422			2,934,190			120,062,036			173.6

The prices used to calculate reserves and future cash flows from reserves for oil, NGL and natural gas, respectively, were as follows: September 30, 2018 - $62.86/Bbl, $26.13/Bbl, $2.56/Mcf; September 30, 2017 - $46.31/Bbl, $17.55/Bbl, $2.81/Mcf; September 30, 2016 - $36.77/Bbl, $12.22/Bbl, $1.97/Mcf.

The revisions of previous estimates from 2017 to 2018 were primarily the result of:

Extensions, discoveries and other additions from 2017 to 2018 are principally attributable to:

	Proved Developed Reserves						Proved Undeveloped Reserves
	Oil		NGL		Natural Gas		Oil		NGL		Natural Gas
	(Barrels)		(Barrels)		(Mcf)		(Barrels)		(Barrels)		(Mcf)
September 30, 2016		1,980,519		1,095,256		62,929,047		3,445,571		527,447		18,796,551
September 30, 2017		2,201,528		1,768,425		87,861,043		3,308,139		616,274		33,334,077
September 30, 2018		2,334,587		2,085,706		83,151,954		3,649,835		848,484		36,910,082

The following details the changes in proved undeveloped reserves for 2018 (Mcfe):

Beginning PUD reserves were 56.9 Bcfe. A total of 2.2 Bcfe (4% of the beginning balance) was transferred to proved developed during 2018. In the last two years, 41% of the beginning PUD reserves were transferred to proved developed. The 12.5 Bcfe (22% of the beginning balance) of negative revisions to PUD reserves were pricing revisions of 0.7 Bcfe and performance revision of 11.8 Bcfe, predominately resulting from the removal of oil, NGL and natural gas reserves associated with Eagle Ford wells that are no longer projected to be developed within 5 years from the date they were added due to a delayed drilling program in 2018. We anticipate that all the Company’s current PUD locations will be drilled and converted to PDP within five years of the date they were added. However, PUD locations and associated reserves, which are no longer projected to be drilled within five years from the date they were added to PUD reserves, will be removed as revisions at the time that determination is made. In the event that there are undrilled PUD locations at the end of the five-year period, it is our intent to remove the reserves associated with those locations from our proved reserves as revisions. The Company added 20.4 Bcfe of PUD reserves in 2018 primarily within the Company’s active drilling program areas of 1) the Anadarko Basin Woodford Shale in western Oklahoma, 2) the Anadarko Basin STACK Meramec in western Oklahoma and 3) the current drilling program of the Eagle Ford Shale in Texas. These additions result from continuing development and additional well performance data in each of the referenced plays. Of the 2018 PUD adds, 1.2 Bcfe was drilling or completing at year-end.

Accounting Standards prescribe guidelines for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. The Company has followed these guidelines, which are briefly discussed below.

Future cash inflows and future production and development costs are determined by applying the trailing unweighted 12-month arithmetic average of the first-day-of-the-month individual product prices and year-end costs to the estimated quantities of oil, NGL and natural gas to be produced. Actual future prices and costs may be materially higher or lower than the unweighted 12-month arithmetic average of the first-day-of-the-month individual product prices and year-end costs used. For each year, estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced, based on continuation of the economic conditions applied for such year.

Estimated future income taxes are computed using current statutory income tax rates, including consideration for the current tax basis of the properties and related carry forwards, giving effect to permanent differences and tax credits. The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor. The assumptions used to compute the standardized measure are those prescribed by the FASB and, as such, do not necessarily reflect our expectations of actual revenue to be derived from those reserves nor their present worth. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates affect the valuation process.

	2018			2017			2016
Future cash inflows	$	759,899,074		$	637,509,599		$	380,263,695
Future production costs		(259,413,766	)		(256,193,675	)		(182,948,045	)
Future development and asset retirement costs		(89,518,449	)		(93,133,683	)		(72,431,842	)
Future income tax expense		(95,872,182	)		(102,193,819	)		(38,674,100	)
Future net cash flows		315,094,677			185,988,422			86,209,708

10% annual discount		(158,768,823	)		(105,155,847	)		(56,439,589	)
Standardized measure of discounted future net cash flows	$	156,325,854		$	80,832,575		$	29,770,119

Changes in the standardized measure of discounted future net cash flows are as follows:

	2018			2017			2016
Beginning of year	$	80,832,575		$	29,770,119		$	81,591,211
Changes resulting from:
Sales of oil, NGL and natural gas, net of production costs		(32,836,007	)		(25,783,055	)		(16,749,632	)
Net change in sales prices and production costs		47,533,281			37,186,619			(86,198,778	)
Net change in future development and asset retirement costs		1,580,942			(7,939,156	)		21,636,258
Extensions and discoveries		34,667,557			38,582,908			11,640,704
Revisions of quantity estimates		(8,391,223	)		15,282,587			(41,716,689	)
Acquisitions (divestitures) of reserves-in-place		(307,472	)		(962,667	)		-
Accretion of discount		12,602,209			4,789,294			14,424,032
Net change in income taxes		(3,057,128	)		(27,070,430	)		44,533,277
Change in timing and other, net		23,701,120			16,976,356			609,736
Net change		75,493,279			51,062,456			(51,821,092	)
End of year	$	156,325,854		$	80,832,575		$	29,770,119